U.S. patent number 7,271,131 [Application Number 10/656,047] was granted by the patent office on 2007-09-18 for fluid loss control and sealing agent for drilling depleted sand formations.
This patent grant is currently assigned to Baker Hughes Incorporated. Invention is credited to Dennis K. Clapper, William S. Halliday, David Schwertner, Tao Xiang.
United States Patent |
7,271,131 |
Halliday , et al. |
September 18, 2007 |
Fluid loss control and sealing agent for drilling depleted sand
formations
Abstract
An oil-based drilling fluid having a polymer latex capable of
providing a deformable latex film on at least a portion of a
subterranean sand formation has been discovered to inhibit or
control fluid loss and act as a sealing agent when used to drill in
sand formations for hydrocarbon recovery operations. Typically, the
polymer latex is an aqueous suspension of particles formed by
emulsion polymerization that is in turn emulsified into a
hydrocarbon base fluid. The polymer particles of suitable size
precipitate onto the pores of a subterranean sand formation to at
least partial seal the formation with a deformable polymer
film.
Inventors: |
Halliday; William S. (Cypress,
TX), Schwertner; David (The Woodlands, TX), Xiang;
Tao (Houston, TX), Clapper; Dennis K. (Houston, TX) |
Assignee: |
Baker Hughes Incorporated
(Houston, TX)
|
Family
ID: |
34312654 |
Appl.
No.: |
10/656,047 |
Filed: |
September 5, 2003 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20040132625 A1 |
Jul 8, 2004 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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09785842 |
Mar 9, 2004 |
6703351 |
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Current U.S.
Class: |
507/118; 507/125;
507/119 |
Current CPC
Class: |
C09K
8/502 (20130101); C09K 8/32 (20130101); C09K
8/36 (20130101) |
Current International
Class: |
C09K
8/36 (20060101) |
Field of
Search: |
;507/118,125,119 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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0 175 412 |
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Mar 1988 |
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EP |
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2074636 |
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Nov 1981 |
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GB |
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2 131 067 |
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Jun 1984 |
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GB |
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2131067 |
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Jun 1984 |
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GB |
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2304754 |
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Mar 1997 |
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GB |
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2351986 |
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Jan 2001 |
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GB |
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WO93/09201 |
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May 1993 |
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WO |
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Other References
C Stowe, et al., "Laboratory Pore Pressure Transmission Testing of
Shale," AADE National Drilling Technical Conference, 2001, pp.
1-10, AADE 01-NC-HO-44. cited by other .
British Combined Search and Examination Report for United Kingdom
Patent Application No. GB 0114390.8, Oct. 15, 2001. cited by
other.
|
Primary Examiner: Tucker; Philip C.
Attorney, Agent or Firm: Madan, Mossman & Sriram
P.C.
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATION
This application is a continuation-in-part of U.S. patent
application Ser. No. 09/785,842 filed on Feb. 16, 2001, now issued
Mar. 9, 2004 as U.S. Pat. No. 6,703,351 B2.
Claims
We claim:
1. An oil-based drilling fluid for use in sealing sand formations
comprising: a) a polymer latex capable of providing a deformable
latex film on at least a portion of a subterranean formation, the
latex comprising polymer particles in an aqueous continuous phase,
where the polymer particles are selected from the group consisting
of polyvinylacetate copolymer, polyvinyl acetate/vinyl
chloride/ethylene copolymer, polyvinyl acetate/ethylene copolymer,
polydimethylsiloxane, and mixtures thereof; b) a hydrocarbon base
fluid; and c) an emulsifier.
2. The oil-based drilling fluid of claim 1 where the polymer
particles in the latex average between about 0.8 to less than 10
microns in size.
3. The oil-based drilling fluid of claim 1 where the latex
particles are in a size distribution where the majority of the
particles range from more than 10 to less than 100 microns.
4. The oil-based drilling fluid of claim 1 where the polymer latex
is capable of providing a deformable latex seal on at least a
portion of a subterranean sand formation.
5. The oil-based drilling fluid of claim 1 where the polymer latex
is present in the drilling fluid in an amount of from about 0.1 to
about 10 volume % based on the total oil-based drilling fluid.
6. The oil-based drilling fluid of claim 5 where the polymer
particles in the latex comprises particles that average about 1
microns to less than 100 microns in size.
7. An oil-based drilling fluid for use in sealing subterranean sand
formations comprising: a) from about 1 to about 10 volume % of a
polymer latex having particles selected from the group consisting
of polyvinylacetate copolymer, polyvinyl acetate/vinyl
chloride/ethylene copolymer, polyvinyl acetate/ethylene copolymer,
polydimethylsiloxane, and mixtures thereof in an aqueous continuous
phase, where the polymer latex is capable of providing a deformable
latex film on at least a portion of a subterranean formation; b) a
hydrocarbon base fluid; and f) an emulsifier in an amount effective
to keep the latex suspended in the oil-based drilling fluid.
8. A method of inhibiting fluid loss of an oil-based drilling fluid
in a sand formation, the method comprising: a) providing an
oil-based drilling fluid comprising: i) a polymer latex capable of
providing a deformable latex film on at least a portion of a
subterranean formation, the latex comprising polymer particles in
an aqueous continuous phase, where the polymer particles are in a
size distribution where the majority of the particles range from
about 1 to less than 100 microns; ii) a hydrocarbon base fluid; and
iii) an emulsifier; and b) circulating the oil-based drilling fluid
in contact with a borehole wall in a sand formation.
9. The method of claim 8 where in providing the oil-based drilling
fluid the polymer particles in the latex average from about 1 to 10
microns in size.
10. The method of claim 8 where in providing the oil-based drilling
fluid, the polymer latex is capable of providing a deformable latex
seal on at least a portion of a subterranean sand formation and the
polymer particles are selected from the group consisting of
polymethyl methacrylate, polyethylene, carboxylated
styrene/butadiene copolymer, polyvinylacetate copolymer, polyvinyl
acetate/vinyl chloride/ethylene copolymer, polyvinyl
acetate/ethylene copolymer, natural latex, polyisoprene,
polydimethylsiloxane, and mixtures thereof.
11. The method of claim 8 where in providing the oil-based drilling
fluid, the polymer latex is present in the drilling fluid in an
amount of from about 0.1 to about 10 vol. % based on the total
oil-based drilling fluid.
12. A method of inhibiting fluid loss of an oil-based drilling
fluid in a sand formation, the method comprising: a) providing an
oil-based drilling fluid comprising: i) from about 0.1 to about 10
vol. % of a polymer latex comprising polymer particles in an
aqueous continuous phase where the polymer particles are selected
from the group consisting of polymethyl methacrylate, polyethylene,
carboxylated styrene/butadiene copolymer, polyvinylacetate
copolymer, polyvinyl acetate/vinyl chloride/ethylene copolymer,
polyvinyl acetate/ethylene copolymer, natural latex, polyisoprene,
polydimethylsiloxane, and mixtures thereof and are in a size
distribution where the majority of the particles range from about 1
to less than 100 microns; ii) a hydrocarbon base fluid; and iii) an
emulsifier; and where the proportion is based on the total
oil-based drilling fluid; and b) circulating the oil-based drilling
fluid in contact with a borehole wall in a sand formation.
Description
FIELD OF THE INVENTION
The present invention relates to oil-based drilling fluids used
during petroleum recovery operations, and more particularly
relates, in one embodiment, to using oil-based drilling fluids
containing additives to inhibit fluid loss in the drilling of
depleted sand formations.
BACKGROUND OF THE INVENTION
Drilling fluids used in the drilling of subterranean oil and gas
wells as well as other drilling fluid applications and drilling
procedures are known. In rotary drilling there are a variety of
functions and characteristics that are expected of drilling fluids,
also known as drilling muds, or simply "muds". The drilling fluid
is expected to carry cuttings up from beneath the bit, transport
them up the annulus, and allow their separation at the surface
while at the same time the rotary bit is cooled and cleaned. A
drilling mud is also intended to reduce friction between the drill
string and the sides of the hole while maintaining the stability of
uncased sections of the borehole. The drilling fluid is formulated
to prevent unwanted influxes of formation fluids from permeable
rocks penetrated and also often to form a thin, low permeability
filter cake which temporarily seals pores, other openings and
formations penetrated by the bit. The drilling fluid may also be
used to collect and interpret information available from drill
cuttings, cores and electrical logs. It will be appreciated that
within the scope of the claimed invention herein, the term
"drilling fluid" also encompasses "drill-in fluids".
Drilling fluids are typically classified according to their base
material. In water-based muds, solid particles are suspended in
water or brine. Oil can be emulsified in the water or brine.
Nonetheless, the water is the continuous phase. Oil-based muds are
the opposite. Solid particles are suspended in oil and water or
brine is emulsified in the oil and therefore the oil is the
continuous phase. Oil-based muds that are water-in-oil emulsions
are also called invert emulsions. Brine-based drilling fluids, of
course are a water-based mud in which the aqueous component is
brine.
Optimizing high performance water base mud design is commonly at
the forefront of many drilling fluid service and oil operating
companies' needs due to the various limitations of invert emulsion
fluids. Invert emulsion fluids formulated with traditional diesel,
mineral or the newer synthetic oils are the highest performing
drilling fluids with regard to shale inhibition, borehole
stability, and lubricity. Various limitations of these fluids,
however, such as environmental concerns, economics, lost
circulation tendencies, kick detection, and geologic evaluation
concerns maintains a strong market for high performance water based
fluids. Increased environmental concerns and liabilities continue
to create an industry need for water based drilling fluids to
supplement or replace the performance leading invert emulsion mud
performance.
A particular problem when drilling into shale formations with
water-based fluids is the pore pressure increase and swelling from
penetration of the shale by the fluid. Shale stabilizers are
typically added to the mud to inhibit these phenomena and to
stabilize the shale from being affected by the mud.
Reducing drilling fluid pressure invasion into the wall of a
borehole is one of the most important factors in maintaining
wellbore stability. It is recognized that sufficient borehole
pressure will stabilize shales to maintain the integrity of the
borehole. When mud or liquid invades the shale, the pressure in the
pores rises and the pressure differential between the mud column
and the shale falls. With the drop in differential pressure, the
shale is no longer supported and can easily break off and fall into
the well bore. Likewise, the invasion of water into the shale
matrix increases hydration or wetting of the partially dehydrated
shale body causing it to soften and to lose its structural
strength. Chemical reactivity can also lead to instability. There
is always a need for a better composition and method to stabilize
the shale formations.
There is an analogous need to seal and prevent fluid loss control
when recovering hydrocarbons from sand formations, particularly
depleted sand formations. Depleted sand formations are productive,
or formerly productive, hydrocarbon zones that have been produced,
drawn down, or otherwise depleted of their content, creating a
lower formation pressure than that of the fluid which may be in use
in the well. Because of this pressure differential, it is important
to partially or completely seal the sand formation to inhibit or
prevent fluid loss of the mud into the sand.
It is apparent to those selecting or using a drilling fluid for oil
and/or gas exploration that an essential component of a selected
fluid is that it be properly balanced to achieve all of the
necessary characteristics for the specific end application. Because
the drilling fluids are called upon to do a number of tasks
simultaneously, this desirable balance is difficult to achieve.
It would be desirable if compositions and methods could be devised
to aid and improve the ability of drilling fluids to simultaneously
accomplish these tasks.
SUMMARY OF THE INVENTION
Accordingly, it is an object of the present invention to provide
methods and compositions to at least partially seal subterranean
sand formations when conducting hydrocarbon recovery operations
with oil-based drilling fluids.
It is another object of the present invention to provide oil-based
drilling fluids that reduce the rate of drilling fluid pressure
invasion into the borehole wall.
Still another object of the invention is to provide a composition
and method that increase the pressure blockage and reliability of
sand formation seals that can be accomplished with oil-based
fluids.
In carrying out these and other objects of the invention, there is
provided, in one form, an oil-based drilling fluid for use in
sealing sand formations that includes a polymer latex that is
capable of providing a deformable latex film on at least a portion
of a subterranean formation. The latex includes polymer particles
in an aqueous continuous phase. The oil based drilling fluid
additionally includes a hydrocarbon base fluid and an
emulsifier.
In another non-limiting embodiment of the invention, there is
provided, in one form, a method of inhibiting fluid loss of an
oil-based drilling fluid in a sand formation, where the method
involves providing an oil-based drilling fluid. The oil-based
drilling fluid includes a polymer latex capable of providing a
deformable latex film on at least a portion of a subterranean
formation. In turn, the latex includes polymer particles in an
aqueous continuous phase. The oil-based drilling fluid also
includes a hydrocarbon base fluid and an emulsifier. The method
additionally comprises circulating the oil-based drilling fluid in
contact with a borehole wall.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 shows a chart of the formation pressure as a function of
time for a pressure invasion test using various intermediate test
formulations;
FIG. 2 is a graph of the surfactant effect on GENCAL 7463 particle
size in 20% NaCl/1 lb/bbl NEWDRILL PLUS/1 lb/bbl XAN-PLEX D/0.5
lb/bbl sodium gluconate/3 lb/bbl NaAlO2/5% by volume GENCAL
7463;
FIG. 3 is a graph of the influence of polymer resins (3 lb/bbl) on
GENCAL 7463 particle size distributions after 16 hours, 150.degree.
F. hot roll in 20% NaCl/0.75 lb/bbl XAN-PLEX D/0.5 lb/bbl sodium
D-gluconate/0.4 lb/bbl NEW-DRILL PLUS/2 lb/bbl BIO-PAQ/3 lb/bbl
NaAlO2/3% GENCAL 7463/1 lb/bbl EXP-152;
FIG. 4 is a graphical comparison of the effects on mud properties
for EXP-154 versus ALPLEX in 12 lb/gal mud; the base mud was 20%
NaCl/0.5 lb/bbl XAN-PLEX D/2 lb/bbl BIO-LOSE/1 lb/bbl NEW-DRILL
PLUS/3% EXP-155/150 lb/bbl MIL-BAR/27 lb/bbl Rev Dust;
FIG. 5 is a graph of PPT test results for ALPLEX, EXP-154/EXP-155,
and ISO-TEQ fluids;
FIG. 6 is a graph showing the effect of circulation on
EXP-154/EXP-155 mud performance;
FIG. 7 is a graph showing the effect of latex on mud properties in
9.6 lb/gal 20% NaCl fluid after 16 hours, 250.degree. F.
(121.degree. C.) hot roll; the base fluid was 20% NaCl/1 lb/bbl
XAN-PLEX D/0.4 lb/bbl NEW-DRILL PLUS/2 lb/bbl BIO-PAQ/5 lb/bbl
EXP-154/10 lb/bbl MIL-CARB/27 lb/bbl Rev Dust;
FIG. 8 is a graph showing the effect of latex on mud properties in
12 lb/gal after hot rolling for 16 hours at 250.degree. F.
(121.degree. C.); the base fluid was 20% NaCl/0.75 lb/bbl XAN-PLEX
D/0.4 lb/bbl NEW-DRILL PLUS/3 lb/bbl BIO-PAQ/5 lb/bbl EXP-154/150
lb/bbl MIL-CARB/27 lb/bbl Rev Dust; and
FIG. 9 is a graph of 96 hour Mysidopsis bahia range-finder results
for experimental products in 12 lb/gal fluids where the base fluid
is 20% NaCl/0.5 lb/bbl XAN-PLEX D/0.4-1 lb/bbl NEW-DRILL PLUS/2
lb/bbl MIL-PAC LV (or BIO-PAQ)/150 lb/bbl MIL-BAR;
FIG. 10 is a graph of polymer particle size distribution of
MAX-SEAL in a polyolefin hydrocarbon base fluid;
FIG. 11 is a chart of the effect of MAX-SEAL on PPA test results at
250.degree. F. (121.degree. C.) for 14 lb/gal SYN-TEQ mud on
different permeability disks, where the mud samples have been hot
rolled at 250.degree. F. (121.degree. C.) for 16 hours; and
FIG. 12 is a graph of the effect of MAX-SEAL on the PPA fluid loss
at 250.degree. F. (121.degree. C.) on 0.4 Darcy disk for 14 ppg
SYN-TEQ mud, where the mud samples have been hot rolled at
250.degree. F. (121.degree. C.) for 16 hours.
DETAILED DESCRIPTION OF THE INVENTION
It has been discovered that a polymer latex added to a water-based
drilling fluid can reduce the rate the drilling fluid pressure
invades the borehole wall of a subterranean formation during
drilling. The polymer latex preferably is capable of providing a
deformable latex film or seal on at least a portion of a
subterranean formation. Within the context of this invention, the
terms "film" or "seal" are not intended to mean a completely
impermeable layer. The seal is considered to be semi-permeable, but
nevertheless at least partially blocking of fluid transmission
sufficient to result in a great improvement in osmotic efficiency.
In a specific, non-limiting embodiment, a submicron polymer latex
added to a high salt water-based mud containing an optional, but
preferred combining/precipitating agent, such as an aluminum
complex will substantially reduce the rate of mud pressure
penetration into shale formations. The pressure blockage,
reliability, magnitude and pore size that can be blocked are all
increased by the latex addition. Inhibiting drilling fluid pressure
invasion into the wall of a borehole is one of the most important
factors in maintaining wellbore stability.
It has been additionally discovered that the polymer latex systems
of this invention can be incorporated into oil-based drilling
fluids. However, it has been discovered that in these fluids, the
polymer latex seals can be formed without the need for a
precipitating agent, a surfactant or any salt in the water phase.
The latex, where generally water or other aqueous component is the
continuous phase, is in turn suspended in a hydrocarbon base fluid
having at least an amount of emulsifier sufficient to suspend the
polymer latex therein. In one non-limiting embodiment of the
invention, the polymer latex may simply be mixed with the
hydrocarbon base fluid without the need for adding any more
emulsifier than is normally present in such fluids.
The components of the water-based drilling fluids of this invention
are the polymer latex and water, which makes up the bulk of the
fluid. Of course, a number of other common drilling fluid additives
may be employed as well to help balance the properties and tasks of
the fluid.
The polymer latex is preferably a carboxylated styrene/butadiene
copolymer, in a non-limiting example. A particular, non-limiting
carboxylated styrene/butadiene copolymer is GENCAL 7463 available
from Omnova Solution Inc. Other suitable polymer latexes include,
but are not limited to polymethyl methacrylate, polyethylene,
polyvinylacetate copolymer, polyvinyl acetate/vinyl
chloride/ethylene copolymer, polyvinyl acetate/ethylene copolymer,
natural latex, polyisoprene, polydimethylsiloxane, and mixtures
thereof. A somewhat less preferred polymer latex is
polyvinylacetate copolymer latex, more specifically, an
ethylenevinyl chloride vinylacetate copolymer. While
polyvinylacetate copolymer latices will perform within the methods
of this invention, they generally do not perform as well as the
carboxylated styrene/butadiene copolymers. The average particle
size of the polymer latex is less than 1 micron or submicron in one
non-limiting embodiment of the invention, and in another
non-limiting embodiment has a diameter of about 0.2 microns or 0.2
microns or less. Other polymers in the disperse phase may be found
to work. It is anticipated that more than one type of polymer latex
may be used simultaneously. The proportion of the polymer latex in
the drilling mud, based on the total amount of the fluid may range
from about 0.1 to about 10 vol. %, preferably from about 1 to about
8 vol. %, and most preferably from about 2 to about 5 vol. %. These
ranges apply for the embodiment of oil-based drilling fluids as
well.
The optional salt may be any common salt used in brine-based
(aqueous) drilling fluids, including, but not necessarily limited
to calcium chloride, sodium chloride, potassium chloride, magnesium
chloride, calcium bromide, sodium bromide, potassium bromide,
calcium nitrate, sodium formate, potassium formate, cesium formate
and mixtures thereof. By a "high salt content" is meant at least 20
weight percent, and saturated brine solutions are preferred in one
non-limiting embodiment. It will appreciated that it is impossible
to predict in advance what the salt content of a particular
saturated brine solution will be since the saturation point depends
on a number of factors including, but not limited to the kinds and
proportions of the various components of the water-based fluid. The
salt is optional because the invention will perform without it,
that is, using fresh water.
Another optional component is precipitating agent. Suitable
precipitating agents include, but are not limited to, silicates,
aluminum complexes, and mixtures thereof. Suitable aluminum
complexes include, but are not limited to, sodium aluminate,
NaAl2O2, sometimes written as Na2OAl2O3, aluminum hydroxide,
aluminum sulfate, aluminum acetate, aluminum nitrate, potassium
aluminate, and the like, and mixtures thereof (especially at pH of
>9 for these compounds to be soluble in water). The proportion
of the precipitating agent in the drilling mud, based on the total
amount of the fluid may range from about 0.25 to about 20 lb/bbl,
preferably from about 1 to about 10 lb/bbl and most preferably from
about 2 to about 7 lb/bbl. Without being limited to a particular
theory, the precipitating agent is believed to chemically bind to
the surface of the clay of the borehole and provide a highly active
polar surface.
Another optional component of the composition of the invention is a
surfactant. If the surfactant is present, the surfactant treated
latex wets the surface strongly and accumulates to form a film or
coating that seals fractures and defects in the shale. Suitable
wetting surfactants include, but are not limited to, betaines,
alkali metal alkylene acetates, sultaines, ether carboxylates, and
mixtures thereof. It has been determined that surfactants are
particularly beneficial when salts are present in the drilling
fluid, and are not as preferred in fresh water fluid systems.
The proportions of these components based on the total water-based
drilling fluid are from about 0.1 to 10 volume % of polymer latex,
at least 1 wt % of salt (if present), from about 0.25 to 20 lb/bbl
of precipitating agent (if present), from about 0.005 to about 2
vol. % of surfactant (if present), the balance being water. In a
more preferred embodiment, the proportions range from about 1 to 8
vol. % of polymer latex, at least 1 wt % of salt (if present), from
about 1 to 10 lb/bbl of precipitating agent (if present) from about
0.01 to about 1.75 vol. % of wetting surfactant (if present), the
balance being water.
It is desired that the sodium aluminate or other precipitating
agent be in a metastable form in the mud, which means that it is in
suspension or solution, but precipitates out upon the borehole
wall. Typically, aluminum compounds have been added to the mud on
site. If added to mud formulations earlier, they tend to be
unstable and precipitate prematurely.
Since the development of pore pressure transmission (PPT) testing,
the effects of various chemical additives on pore pressure
transmission rates have been evaluated. Testing has focused
primarily on the performance of salts, glycols, and precipitating
agents such as silicates and aluminum complexes. Improvements in
PPT test equipment and methods have accompanied the general
interest and search for increasing more efficient water-based mud
systems that approach the PPT test performance of invert emulsion
fluids. While other investigators have found silicate fluids to be
especially effective for reduced poor pressure transmission rates,
silicate fluids have not been widely used due to limitations of
these fluids. Although lower pore pressure transmission rates have
been demonstrated For salts, glycols, and aluminum complexing
agents, these products still do not approach the performance of
invert emulsion fluids.
A combination of a new formulation approach as well as modification
to the PPT test procedure was used to demonstrate the efficacy of
an alternative approach to enhance the performance of water-based
mud systems. Water-dispersible polymers were selected to provide
sources of small, deformable particles to provide a sealing and
blocking effect on the shale. The first of these polymers was
tested on the PPT test in a fluid with other products.
In another embodiment of the invention, the polymer latex is
suspended in a hydrocarbon base fluid, also known as an oil-based
fluid. The hydrocarbon phase may be any suitable hydrocarbon used
in drilling fluid applications including, but not necessarily
limited to diesel, synthetic hydrocarbons, such as isomerized
polyolefins and the like. Hydrocarbon base fluids used as drilling
muds typically contain emulsifiers that are necessary to achieve
the multiple functions of the mud. These emulsifiers are all
suitable to suspend the latex in the hydrocarbon base fluid. The
latex itself is suspended as "particles" in the hydrocarbon base
fluid phase. The size of these particles is typically larger than
the size of the polymer particles in the latex and may range up to
100 microns in one non-limiting embodiment of the invention, and
from about 10 to about 100 or less than 100 microns in an alternate
embodiment. In another non-limiting, alternate embodiment, the
polymer particles per se may range from about 1 to 100 microns in
one non-limiting embodiment, and may range between about 0.3 and 10
microns or less, in another non-limiting embodiment may range from
about 0.8 to less than 10 microns, where in another non-limiting
embodiment, the particles have an average particle size between
about 1 and 10 microns, and more preferably from about 1 to about 7
microns.
The invention will be further illustrated with respect to the
following examples, which are only meant to further illuminate the
invention, and not limit it in any way.
EXAMPLE 1
Fluid Intermediate Preparation
The following Example is the first preparation of the intermediate
compositions of this invention. Unless otherwise noted, the latex
in the Examples is 728 Latex, a polyvinylacetate latex.
TABLE-US-00001 Component Grams per barrel Grams per 7 barrels Tap
water 310 2170 Sodium aluminate 2 14 LIGCO 2 14 AIRFLEX 728 10.5
73.5 (75 cc)
The mixture was hot rolled. After 6 days, the pH was 11.51. The
bottom of the jar was about 75% covered with 1/32'' fines. The
following components were then added, again given in gram
proportions for a single barrel and 7 barrels, respectively:
TABLE-US-00002 NEWDRILL PLUS 0.4 2.8 NaCl (20%) 77.5 540 MILPAC LV
2 14
The fluid with the latex and the NEWDRILL+ had a light brown color.
LD8 was added to control foaming. The resulting mixture was hot
rolled for four hours at 150.degree. F. The final pH was 10.75.
EXAMPLE 2
Shale Pressure Penetration Determination
The pore pressure transmission (PPT) device is based on a 1500 psi
Hassler cell designed for 2.5 cm diameter core plugs from 2.5 cm to
7.5 cm in length. A Hassler cell is a cylinder with a piston
inserted in each end. The core is held between the two pistons. A
rubber sleeve is placed around the core and the pistons to seal
around the core and prevent flow around the core. The outside of
the sleeve is pressured to make a good seal. These tests use a core
25 mm in diameter and 25 mm long.
The low pressure side of the core (formation side) is fitted with a
1 liter, 2000 psi., stainless steel accumulator to provide back
pressure. The high pressure side of the core is connected to two
similar accumulators, one for pore fluid, and one for the test
fluid. The pressure in each accumulator is controlled with a manual
regulator fed by a 2200 psi nitrogen bottle.
All pressures are monitored with Heise transducers. The transducer
pressures are automatically computer logged at preset
intervals.
The cell is enclosed in an insulated chamber and the temperature
maintained with a 200 watt heater. The heater is controlled with a
Dwyer temperature controller driving a Control Concepts phase angle
SCR control unit. Temperature control is accurate to
+/-0.05.degree. C.
A pressure is applied to one end of the core and the flow through
the core is measured. The piston on the low pressure side is filled
with liquid, and blocked, so an increase in liquid pressure is
measured rather than flow. A very small amount of liquid flow
through the core will make a large rise in the pressure, making the
cell sensitive enough to measure flow through shale. Shale has a
very low permeability, so the flow of fluid through it is very
small. Pressure is plotted versus time. Results are expressed as
formation pressure (FP). If the FP increases over time, there is
pressure penetration; if the formation pressure decreases over time
there is not, and the latter is what is desired.
The fluid of Example 1 was used. Three 50% displacements of 50 cc
each were performed during and just after heating up of the test
cell. One run was started at 100% displacement and the temperature
was difficult to control, so it was decided starting at 50% was
better. Temperature=155.degree. F. Borehole side pressure=250 psi
Confining pressure=370 psi
TABLE-US-00003 Time, hours:minutes Formation Pressure, psi 0 48.1
1:30 47.9 2:00 47.6 7:15 50.9
Eventually, 50 cc of fluid was displaced up to 50% within 2.degree.
F. temperature variation. The pressure rose to 52.7 psi. Formation
heat was turned off, and the temperature was 147.degree. F.
Displacement pulled the formation pressure down to 36 psi, then
rose to 80.2 over the next two days. The initial formation pressure
decrease demonstrated that the formulation of the invention
inhibited pressure penetration.
EXAMPLE 3
Fluid Intermediate Preparation--Proportions in Grams Unless
Otherwise Noted
TABLE-US-00004 Component Per barrel Per 7 barrels Tap water 310
2170 cc Sodium aluminate 2 14 LIGCO 2 14 AIRFLEX 728 Latex 10.5 75
cc NEWDRILL PLUS 0.4 2.8 NaCl (20%) 77.5 540 MILPAC LV 2 14
The sodium aluminate and AIRFLEX 728 latex were mixed together and
allowed to stand over the weekend. The mixture was then hot rolled
at 150.degree. F. for two hours. The salt and polymers were then
added. The sequence of addition to the sodium aluminate/latex
mixture was: PHPA (partially hydrolyzed polyacrylamide; NEWDRILL
PLUS), followed by mixing; then half of the salt, followed by
MILPAC LV, followed by the other half of the salt. The mixture was
hot rolled overnight.
EXAMPLE 4
Shale Pressure Penetration Determination
Borehole side pressure=250 psi Confining pressure=370 psi
TABLE-US-00005 Time, hours:minutes Formation Pressure, psi 0 46.3
5:49 2.3 7:36 0.6* 50:00 65.0 *The confining pressure was raised to
410 psi and the borehole pressure was raised to 300 psi at this
point.
EXAMPLES 5 and 6, COMPARATIVE EXAMPLES A-F
Two other inventive formulations (Examples 5 and 6) and six
comparative Examples (A-F) were prepared and tested. The results
are shown in FIG. 1. As indicated the Inventive Examples 5 and 6
both gave the desired results of decreasing formation pressure over
time. The comparative Examples undesirably gave increasing
formation pressures over time. The composition identities are given
on FIG. 1 itself. The designation "CORE: P2 PARALLEL" refers to the
core being Pierre Shale in parallel orientation.
These results verify the necessity of having all three components:
the salt, the latex, and the sodium aluminate (Examples 5 and 6).
Use of the latex alone (comparative Ex. A), use of salt only
(comparative Ex. B), use of the latex together with salt only
(comparative Example C), use of sodium aluminate and the salt only
(comparative Ex. D), use of the sodium aluminate and salt only
(comparative Ex. E), and use of the sodium aluminate with salt only
(comparative Ex. F) were all found to be ineffective, or at least
certainly not as effective as the inventive composition.
Further experimental evidence indicates that some latex products
exhibit a synergistic effect with aluminum complexes that results
in improved pore pressure transmission characteristics. Stable
drilling fluid systems have been formulated with latex that remain
dispersed and flexible in highly saline (high salt content) fluids.
Inventive drilling fluids provide pore pressure transmission
performance closer to oil-based fluids than what is exhibited by
current aluminum-based drilling fluids. Two features of this system
are believed to be the main contributors to shale stabilization.
First, the ultra-fine, deformable latex particles (having a
preferable diameter of about 0.2 microns) mechanically seal shale
micro-fractures and physically prevent further intrusion of
drilling fluids into sensitive shale zones. Secondly, latex
co-precipitation with precipitating agents, if present, such as
aluminum complexes, produces a semi-permeable membrane on shale
surfaces that chemically improves the osmotic efficiency between
the fluid and the borehole.
Three experimental additives were discovered for the inventive
fluids: EXP-153, EXP-154 and EXP-155. EXP-153 is a sulfonated
polymer resin used to control HTHP fluid loss in this system.
EXP-154 is considered an alternative to aluminum complex product
ALPLEX. Compared to ALPLEX, EXP-154 exhibits much better
compatibility with latex fluids. EXP-155 is a modified latex
product. Compared to other commercially available latices EXP-155
displays less sensitivity to electrolytes and does not flocculate
in 20% sodium chloride fluids at temperatures up to 300.degree. F.
(149.degree. C.). Furthermore, due to the wide temperature range
between its glass transition temperature (Tg) and melting point
(Tm), the particles of EXP-155 remain deformable and capable of
plugging shale micro-fractures at most application temperatures.
The toxicities of all of these products meet the requirement for
fluid disposal in the Gulf of Mexico.
Formulations and Fluid Properties
All fluids were mixed according to established Baker Hughes INTEQ
mixing procedures. The initial and final Bingham Plastic
rheological properties of plastic viscosity, yield point, ten
second gels, and ten minute gels were measured by Fann 35
viscometer at 120.degree. F. (49.degree. C.). The initial and final
pH and API filtrate were recorded. HTHP fluid loss at 250.degree.
F. (121.degree. C.) was measured after static and dynamic aging for
16 hours at 250.degree. F. (121.degree. C.).
Latex Stability
The stability of the latex samples were first evaluated in 20% and
26% NaCl solutions by the following procedure: 1. Add 332 ml 20%
(or 26%) NaCl water solution into a mixer cup and start mixing. 2.
Slowly add 18 ml tested latex sample into the solution and adjust
the Prince Castle mixer to 4000 rpm with Variac and tachometer. 3.
After stirring 5 minutes, slowly add 3 grams NaAlO.sub.2 into the
above solution and mix for a total of 20 minutes. During the mixing
period it may be necessary to add about 5 drops defoamer (LD-8) if
foaming is observed. 4. Put this fluid into a jar and statically
age for 16 hours at 150.degree. F. (66.degree. C.). 5. Remove the
jar from the oven and cool to room temperature. Observe the fluid
for flocculation and separation. 6. If there is no separation or
flocculation, sieve the fluid with a 100-mesh (0.150 mm) [please
check this conversion, if possible] screen. Observe sieve for
amount of retained latex particles.
Additional evaluations were performed only for those samples having
passed the above screening test. A Malvern Mastersizer Particle
Size Analyzer was used to measure the particles size distributions
of latex in formulated fluids. The small sample dispersion unit and
the standard refractive index 50HD (Particle R.I.=1.5295, 0.1000
and Dispersant R.I.=1.3300) were used in all of the particle size
distribution tests. 20% NaCl water solution with pH adjusted to
11.5.
Shale Inhibition Test
The shale inhibition characteristics were determined by shale
dispersion tests that included static wafer test, and pore pressure
(PPT) tests. In the PPT test, a preserved Pierre II shale core, 1
inch diameter by 0.9 inch long (2.54 cm.times.2.29 cm long), is
placed between two pistons, as described previously in Example 2.
The circumference of the shale and pistons are sealed with a rubber
sleeve. The plug is oriented with the bedding planes in the
parallel or high permeability direction. Drilling fluid at 300 psi
is displaced through the upstream piston (borehole side) and
seawater at 50 psi is displaced through the downstream piston
(formation side). The seawater in the downstream piston is
contained with a valve. As mud filtrate enters the borehole end of
the plug, connate water in the shale is displaced into the
formation piston.
Latex Stability
As noted above, initial experiments indicated that some latex
products (emulsion polymers) produced synergistic effects with an
aluminum complex, resulting in improved pore pressure transmission
characteristics of the fluids. This result revealed a new approach
to the design of highly inhibitive, water-based fluids. However,
latex is generally considered to be a metastable system. The large
surface of the particles is thermodynamically unstable and any
perturbation affecting the balancing forces stabilizing the polymer
dispersion results in a change in the kinetics of particle
agglomeration. Most commercial latices, which are designed for the
production of synthetic rubber or the application of
painting/coating, are sensitive to increasing electrolytic
concentration and temperature.
As shown in Table I, among 16 latex samples tested in 26% and 20%
NaCl solutions, none of them is stable in 26% NaCl and only AIRFLEX
728 and GENCAL 7463 are relatively stable in 20% NaCl. Clearly, for
successful applications of latex in drilling fluids, latex
stability in high salt environments and at elevated temperatures
must be improved. A common technique used to increase latex
stability in electrolyte solutions is the addition of some
surfactants. FIG. 2 compares the effect of EXP-152 on the particle
size distributions of AIRFLEX 728 with that of GENCAL 7463. These
results indicate that a blend of GENCAL 7463 and EXP-152 may be a
stable product for drilling fluid applications.
TABLE-US-00006 TABLE I Stability Test for Latex Products in NaCl
Solution T.sub.g Stability After 16 Hours Static Aging Ex. Latex
Samples (.degree. C.) 26% NaCl/3 lb/bbl NaAlO.sub.2 20% NaCl/3
lb/bbl NaAlO.sub.2 Vinyl Acetate/Ethylene Vinyl Chloride 7 AIRFLEX
728 0 Flocculation but pass 100 mesh Flocculation/Coagulation Vinyl
Acetate/Ethylene 8 AIRFLEX 426 0 Flocculation/Coagulation
Flocculation/Coagulation 9 AIRFLEX 7200 0 Flocculation/Coagulation
Flocculation/Coagulation 10 VINAC XX-211 N/A
Flocculation/Coagulation Flocculation/Coagulation 11 ELVACE
40722-00 N/A Flocculation/Coagulation Flocculation/Coagulation
Carboxylated Styrene/Butadiene 12 GENCAL 7463 13 Flocculation but
pass 100 mesh Floc. at 150.degree. F. (66.degree. C.) but stable at
75.degree. F. (24.degree. C.) 13 GENCAL 7470 N/A
Flocculation/Coagulation -- 14 GENFLO 576 N/A
Flocculation/Coagulation -- 15 TYLAC 68219 N/A Flocculation but
pass 100 mesh Flocculation but pass 100 mesh 16 TYLAC CPS 812 N/A
Flocculation/Coagulation -- 17 TYCHEM 68710 N/A
Flocculation/Coagulation -- 18 ROVENE 9410 -56 Coagulation
Coagulation 19 ROVENE 6140 -27 Coagulation Coagulation Carboxylated
Acrylic Copolymer 20 SYNTHEMUL CPS N/A Flocculation/Coagulation --
401 21 SYNTHEMUL N/A Flocculation/Coagulation -- 97982
Styrene/Butadiene 22 ROVENE 4823L -51 Coagulation Coagulation
Aluminum Complex
Although a synergistic effect of ALPLEX with latex on stabilizing
shales was confirmed by PPT test results, this system is fragile
and very sensitive to increasing salt concentration and
temperature. It was found that in 20% NaCl solution, 3% AIRFLEX 728
or 3% GENCAL 7463 were flocculated in a few minutes by adding 4
lb/bbl ALPLEX. Prehydration of ALPLEX in fresh water or addition of
some surfactant (e.g. EXP-152) did improve the stability of this
system at low temperatures, but the latex particle size was still
greatly influenced by ALPLEX. Those particles greater than 100
microns in the fluid containing ALPLEX may have partially resulted
from insoluble lignite (a component of ALPLEX). A similar effect
was also observed with GENCAL 7463. Poor solubility and slow
dissolution rate of the lignite in high salt concentrations is
probably the main factor contributing to decreased latex
stability.
In order to find a polymer resin that was compatible with a latex
system additional tests were performed. FIG. 3 shows the effects of
different polymer resins on the particle size distributions of
EXP-155. Among the tested samples, EXP-153 exhibited the best
compatibility with this latex system.
A new aluminum complex product, EXP-154 (a blend of 45% NaAlO2, 45%
EXP-153 and 10% sodium D-gluconate) was invented for the latex
system. FIG. 4 compares the effects on the mud properties for
EXP-154 with ALPLEX in 12 lb/gal 20% NaCl/NEW-DRILL/EXP-155 fluids.
The experimental aluminum complex exhibits improved compatibility
with latex and biopolymers. Additionally, EXP-154 is found to
control filtration, both API and HTHP, better than does ALPLEX.
Pore Pressure Transmission Testing
Borehole stability effects of the experimental latex system were
evaluated with the pore pressure transmission (PPT) tester
previously described. A preserved Pierre II shale plug, 1 inch
diameter by 0.9 inch long (2.54 cm.times.2.29 cm long), is placed
between two pistons, as described previously in Example 2. The
circumference of the shale and pistons sealed with a rubber sleeve.
The plug is oriented with the bedding planes in the parallel or
high permeability direction. Drilling fluid at 300 psi is displaced
through the upstream piston (borehole side) and seawater at 50 psi
is displaced through the downstream piston (formation side). The
seawater in the downstream piston is contained with a valve. As mud
filtrate enters the borehole end of the plug, connate water in the
shale is displaced into the formation piston. This additional water
compresses the water inside the piston causing the pressure to
rise. The pressure increase in the formation piston water is
measured as formation pressure (FP) rise.
The EXP-154/EXP-155 fluid produces the best PPT results to date as
shown in FIG. 5. The top curve is a standard salt/polymer. The next
one down is ALPLEX, the next curve is an EXP-154/AIRFLEX 728
formulation, below that is the EXP-154/EXP-155 formulation, and
finally at the bottom is a 80/20 ISOTEQ fluid, 25% CaCl2, 6 ppb
CARBO-GEL, and 10 ppb OMNI-MUL. Without necessarily being limited
to one explanation, the superior performance of the EXP-154/EXP-155
fluid is believed to be due, at least in part, to its small
particle size. As discussed previously, GENCAL 7463 was more
efficiently dispersed by the EXP-152 resulting in a much greater
percentage of particles smaller than one micron.
A synergistic effect between latex and aluminum complex has also
been observed in these tests. Such results may be related to the
co-precipitation behavior of EXP-155 and EXP-154. It was found that
EXP-154 becomes insoluble at pH<10. At this condition, EXP-155
alone does not precipitate. However, when EXP-154 exists in this
system, EXP-155 will be co-precipitated with EXP-154. Because of
their co-precipitation behavior, deposited particles on the shale
surface are comprised of lipophilic and hydrophilic components.
This multiphase system is capable of creating a semi-permeable
membrane, resulting in a great improvement in osmotic efficiency.
Another characteristic of EXP-155 is that its ultra-fine particles
are elastomer-like over a wide range of temperatures. When
subjected to differential hydraulic pressure, these ultra-fine
particles do not shear or break, but deform and penetrate the
hairline fractures and to form an impermeable seal. At the
temperatures between Tg (glass transition temperature) and Tm
(melting point), most polymers will exhibit rubber-like elasticity.
The glass transition temperature of EXP-155 is 52.degree. F. From
the relationship between Tg and Tm plotted by Boyer, 1963,
reproduced in Billmeyer, Textbook of Polymer Science, Second
Edition, Wiley-Interscience, New York, 1971, p. 230, we can
estimate that Tm of EXP-155 is about 300.degree. F. (422.degree.
K). This temperature range covers most applications in drilling
fluids.
Circulation of the fluid was found to be an important element of
the latex plugging mechanism. This was explored in the tests with
EXP-155. As the formulation was only 1.5% latex particles by volume
(EXP-155 is 50% active), insufficient latex was available in the
mud to produce plugging under static conditions. With circulation,
however, the latex accumulated on the surface and formed a plugging
film. Standard procedure is to circulate the mud about 7 hours
followed by static exposure overnight. Four or five hours without
circulation elapses before the test is started in the morning. This
static period eliminates pressure drift due to temperature effects
by allowing temperature variation from circulation to
equilibrium.
When the test started the formation pressure fell from 50 psi to
zero, increasing the differential pressure from 250 to 300 psi, as
seen in FIG. 6. In about 30 hours, the plug began to leak and the
formation pressure rose. However, additional circulation sealed the
leak in an hour and the pressure again fell to zero. In previous
tests the circulation was stopped after an hour, and the plug
started leaking again after another 30 hours. In this test,
circulation was restarted after the pressure rose to 60 psi in 70
hours (FIG. 6). However, circulation was maintained 5 hours instead
of one as before. With a few hours of continued circulation after
the greater pressure differential was established, the seal was
more stable. The pressure rose only a few psi in 45 hours.
Photomicrographs of the plug face showed latex accumulation along
microfractures in the shale. As the volume and velocity of
filtration flow into these cracks is very small, filtration alone
cannot account for the latex accumulation at the crack throat.
Inside these cracks the clay surface area to filtrate volume ratio
is very large resulting in heavy EXP-154 precipitation. The reason
may relate to the co-precipitation behavior of EXP-154 and EXP-155
as discussed previous, without being limited to any particular
explanation. The precipitation of aluminum complex at pH<19
apparently enhances latex accumulation at the crack throat. When
sufficient latex is deposited to bridge the crack opening, the
fracture is sealed and differential pressure is established across
the latex. The differential pressure consolidates the latex deposit
into a solid seal. Increasing the differential pressure apparently
causes this seal to deform over time (about 30 hours in the case of
the FIG. 6 results) and/or grows additional cracks in the shale and
the shale begins to leak, although the inventors do not necessarily
want to be limited by this explanation. However, additional
circulation rapidly sealed the leaks and reestablished the seal.
Circulating after the full differential pressure was reached formed
a stable seal with only a small pressure rise.
Effect of Latex on Mud Properties
The previous results and discussions deal with latex stability in
drilling fluids and its synergy with aluminum complex in improving
mud inhabitability to shale formations. Besides, improved
performance parameters achieved by the latex products were also
recognized. Two latex samples, Latex A (8:1 blended AIRFLEX 728 and
EXP-152) and EXP-155 (8:1 blended GENCAL 7463 and EXP-152), were
evaluated in 9.6 lb/gal 20% NaCl and 12 lb/gal 20% NaCl fluids. The
effects of adding 3% by volume of these latex products are
illustrated in FIGS. 7 and 8. Without obvious effect on the fluid
rheology, HTHP fluid loss at 250.degree. F. (121.degree. C.)
decreased as much as 45% and 52% in 9.6 lb/gal mud and 35% and 40%
in 12 lb/gal mud by Latex A and EXP-155, respectively. Again,
EXP-155 presents better results that AIRFLEX 728. Additional tests
with EXP-155 are listed in Table II.
TABLE-US-00007 TABLE II Typical Performance Parameters of 12 lb/gal
20% NaCl/EXP-155 Fluids Formulation Example # 23 24 Water, bbl 0.89
0.89 XAN-PLEX D, lb/bbl 0.5 0.5 BIO-PAQ, lb/bbl 4 -- BIO-LOSE,
lb/bbl -- 4 NEW DRILL PLUS, lb/bbl 1 1 EXP-154, lb/bbl 5 5 NaCl,
lb/bbl 77.5 77.5 EXP-155, % by vol. 3 3 MIL-BAR, lb/unweighted 150
150 bbl Rev-Dust, lb/bbl 27 27 Initial Properties PV, cP 22 21 YP,
lb/100 ft.sup.2 26 20 10 second gel, lb/100 ft.sup.2 5 4 10 minute
gel, lb/100 ft.sup.2 10 8 API, cm.sup.3/30 min 2.5 1.4 pH 10.6 10.7
Density, lb/gal 12.2 12.2 after HR 16 hr @ 150.degree. F.
250.degree. F. -- 150.degree. F. 250.degree. F. -- (66.degree. C.)
(121.degree. C.) (66.degree. C.) (121.degree. C.) after static aged
16 hr @ -- -- 300.degree. F. -- -- 300.degree. F. (149.degree. C.)
(149.degree. C.) PV, cP 20 21 22 26 24 23 YP, lb/100 ft.sup.2 24 29
34 17 21 22 10 second gel, lb/100 ft.sup.2 6 7 10 4 5 5 10 minute
gel, lb/100 ft.sup.2 9 10 13 7 7 7 API, ml 2.8 3.7 2.8 2.2 2.6 1.8
pH 10.4 9.7 9.7 10.5 9.7 10.1 HTHP fluid loss, cm.sup.3/30 min. 9.4
16.4 12 8.4 13 10.8
Toxicity Test
The 96 hour range-finder bioassay results of AIRFLEX 728, GENCAL
7463, EXP-152, EXP-154 and EXP-155 in 12 lb/gal 20% NaCl/NEW-DRILL
fluids are presented in FIG. 9. All products meet the requirement
for fluid disposal in the Gulf of Mexico (30,000 ppm) and become
less toxic after solids contamination.
Use of Polymer Latices in Oil-Based Fluids
In another non-limiting embodiment of the invention, it has been
discovered that polymer lattices within the scope of this
invention, such as MAX-SEAL, may be used as a sealing agent in oil
base fluids when drilling depleted sand formation where mud loss
might occur. This embodiment of the invention may also be used in
at least partially sealing subterranean sand formations during
other hydrocarbon recovery operations.
FIG. 10 shows the particle size distribution of MAX-SEAL in ISO-TEQ
synthetic polyolefin drilling fluid. MAX-SEAL is dispersible in
oil. Most particles of MAX-SEAL are in the range from 0.5 to 10
microns. The particles above 10 microns may come from the water in
MAX-SEAL.
The compatibility of MAX-SEAL with oil base mud has been tested in
14 lb/gal (1700 kg/m.sup.3) SYN-TEQ mud. Table III gives the mud
formulations with and without MAX-SEAL. After aging at 250.degree.
F. (121.degree. C.) for 16 hours, the mud sample with 3% MAX-SEAL
was homogenous. The sealing ability of MAX-SEAL has been evaluated
with a particle plugging apparatus (PPA) tests at 250.degree. F.
(121.degree. C.) and 1000 psi (7,000 kPa) pressure differential
using 0.4, 2 and 20 darcies cement disks respectively and the
results are shown in FIG. 11.
The sealing ability of MAX-SEAL increases with decrease in
permeability. MAX-SEAL might be used with the best efficiency when
drilling some low permeable depleted sand formation. Because of
this deformable property, MAX-SEAL can seal very small pores and
reduce the fluid losses of oil base mud in low permeable depleted
sand formations where other lost circulation material (LCM) might
not work effectively. As shown by FIG. 12, without MAX-SEAL, the
fluid loss rate through a 0.4 Darcies disk reached a constant after
two hours. In contrast, the fluid loss rate of the mud with 3%
MAX-SEAL continually decreased with time and finally reached to
zero.
TABLE-US-00008 TABLE III Formulations and Properties of 14 lb/gal
(1700 kg/m.sup.3) SYN-TEQ with and without MAX-SEAL SYN-TEQ Base
Base + 3% MAX-SEAL Formulation # 25 26 ISO-TEQ, bbl (m.sup.3) 0.57
(0.09) 0.57 (0.09) CARBO-GEL, lb/bbl (g/l) 2 (5.7) 2 (5.7) OMNI-MUL
US, lb/bbl (g/l) 16 (45) 16 (45) 28% CaCl.sub.2, bbl (m.sup.3) 0.1
(0.016) 0.1 (0.016) MIL-BAR, lb/bbl (g/l) 327 (935) 327 (935)
CARBOTEC S, lb/bbl (g/l) 1 (3) 1 (3) Rev Dust, lb/bbl (g/l) 27 (77)
27 (77) MAX-SEAL, % by vol. -- 3 Initial Properties 600 rpm @
120.degree. F. (49.degree. C.) 62 81 300 rpm 35 47 200 rpm 25 36
100 rpm 16 24 6 rpm 5 9 3 rpm 4 7 PV, cP (Pa-s) 27 (0.027) 34
(0.034) YP, lb/100 ft.sup.2 (N/m) 8 (3.9) 13 (6.3) 10'' Gel, lb/100
ft.sup.2 (N/m) 6 (2.9) 10 (4.9) 10' Gel, lb/100 ft.sup.2 (N/m) 7
(3.4) 12 (5.8) Density, lb/gal (g/l) 14.4 (41.2) 14.2 (40.6)
Electric Stability 882 995 HTHP@250.degree. F. (121.degree. C.)on
0.4 Darcy 21 7 Disk, ml/30 min After HR @ 250.degree. F.
(121.degree. C.) for 16 hours 600 rpm @ 120.degree. F. (121.degree.
C.) 77 96 300 rpm 45 59 200 rpm 35 45 100 rpm 23 30 6 rpm 9 11 3
rpm 7 9 PV, cP Pa-s 32 (0.032) 37 (0.037) YP, lb/100 ft.sup.2 (N/m)
13 (6.3) 22 (11) 10'' Gel, lb/100 ft.sup.2 (N/m) 11 (5.4) 13 (6.3)
10' Gel, lb/100 ft.sup.2 (N/m) 13 (6.3) 17 (8.3) Density, lb/gal
(g/l) 14.4 (41.2) 14.2 (40.6) Electric Stability 1073 895
PPA@250.degree. F. (121.degree. C.)on 0.4 Darcy Disk (Spurt: 4 ml)
(Spurt: 2 ml) (3 .mu.), ml/30 min 17 ml 7 ml PPA@250.degree. F.
(121.degree. C.)on 2 Darcy Disk (Spurt: 3.5 ml) (Spurt: 3.5 ml) (10
.mu.), ml/30 min 17.5 ml 8.5 ml PPA@250.degree. F. (121.degree.
C.)on 20 Darcy Disk (Spurt: 3.5 ml) (Spurt: 3.5 ml) (60 .mu.),
ml/30 min 15.5 ml 13 ml Note: After HR the sample with 3% MAX-SEAL
was homogeneous and without any flocculation of MAX-SEAL.
In the foregoing specification, the invention has been described
with reference to specific embodiments thereof, and has been
demonstrated as effective in providing a water-based or oil-based
drilling fluid that can effectively reduce the rate of drilling
fluid pressure invasion of the borehole wall or partially or
completely seal a subterranean sand formation. However, it will be
evident that various modifications and changes can be made thereto
without departing from the broader spirit or scope of the invention
as set forth in the appended claims. Accordingly, the specification
is to be regarded in an illustrative rather than a restrictive
sense. For example, specific combinations of brines or hydrocarbon
base fluids and latexes and with optional emulsifiers,
precipitating agents and/or wetting surfactants or salts falling
within the claimed parameters, but not specifically identified or
tried in a particular composition to reduce mud pressure
penetration into shale or sand formations, are anticipated to be
within the scope of this invention.
GLOSSARY
4025-70 Low molecular weight amphoteric polymer sold by Amoco,
found to be ineffective (also abbreviated as 4025). AIRFLEX 728 A
polyvinylacetate latex (more specifically, an ethylenevinyl
chloride vinylacetate copolymer) dispersion sold by Air Products.
AIRFLEX 426 Vinyl acetate/ethylene copolymer available from Air
Products. AIRFLEX 7200 Vinyl acetate/ethylene copolymer available
from Air Products. ALPLEX.RTM. Proprietary aluminum complex product
available from Baker Hughes INTEQ. AqS Abbreviation for AQUACOL-S,
a glycol available from Baker Hughes INTEQ. BIO-LOSE Derivatized
starch available from Baker Hughes INTEQ. BIOPAQ Derivatized starch
fluid loss additive available from Baker Hughes INTEQ. CARBO-GEL An
amine-treated clay marketed by Baker Hughes INTEQ. CARBO-MUL Invert
emulsion emulsifier marketed by Baker Hughes INTEQ. CARBOTEC S
Emulsifier marketed by Baker Hughes INTEQ. ELVACE 40722-00
Vinylacetate/ethylene copolymer latex available from Reichhold.
EXP-152 Oleamidopropyl betaine surfactant. EXP-153 Sulfonated
polymer resin (or sulfonated humic acid with resin) available from
Baker Hughes INTEQ. EXP-154 A mixture of 45% NaAlO.sub.2, 45%
EXP-153 and 10% sodium D-gluconate. EXP-155 An 8:1 volume blend of
GENCAL 7463 and EXP-152. FLOWZAN Biopolymer available from Drilling
Specialties. FT-1 A SULFATROL, 90% water-soluble sulfated asphalt
dispersion sold by Baker Hughes INTEQ. GENCAL 7463 Carboxylated
styrene/butadiene available from Omnova Solution Inc. GENCAL 7470
Carboxylated styrenelbutadiene available from Omnova Solution Inc.
GENFLO 576 Available from Omnova Solution Inc. ISOTEQ.TM.
Synthetic, biodegradable, non-toxic, isomerized polyolefin-based
drilling fluid available from Baker Hughes INTEQ. LD8 A commercial
defoamer available from Baker Hughes INTEQ. LIGCO Lignite sold by
Baker Hughes INTEQ. MAX-SEAL.TM. An aqueous suspension of sealing
polymers available from INTEQ Drilling Fluids of Baker Hughes
Incorporated. MIL-BAR Barite weighting agent available from Baker
Hughes INTEQ. MIL-CARB Calcium carbonate weighting agent available
from Baker Hughes INTEQ. MILPAC LV Low viscosity polyamine
cellulose available from Baker Hughes INTEQ (sometimes abbreviated
as PacLV). NEWDRILL PLUS Partially hydrolyzed polyacrylamide
available from Baker Hughes INTEQ. OMNI-MUL.TM. A non-ionic
emulsifier and wetting agent available from Baker Hughes INTEQ.
ROVENE 4823L Styrene/butadiene copolymer available from Mallard
Creek. ROVENE 6140 Carboxylated styrene/butadiene available from
Mallard Creek. ROVENE 9410 Carboxylated styrene/butadiene available
from Mallard Creek. SA Abbreviation for sodium aluminate.
SYN-TEC.sup.SM Drilling fluid systems available from Baker Hughes
INTEQ incorporating ISO-TEQ polyolefin-based drilling fluids along
with other specialized fluid additives. SYNTHEMUL 97982
Carboxylated acrylic copolymer available from Reichhold. SYNTHEMUL
CPS 401 Carboxylated acrylic copolymer available from Reichhold.
TYCHEM 68710 Carboxylated styrene/butadiene copolymer available
from Reichhold. TYLAC 68219 Carboxylated styrene/butadiene
copolymer available from Reichhold. TYLAC CPS 812 Carboxylated
styrene/butadiene copolymer available from Reichhold. VINAC XX-211
Vinyl acetate/ethylene copolymer available Air Products. XAN-PLEX D
Biopolymer available from Baker Hughes INTEQ.
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